Well re-fracturing method

ABSTRACT

A method of re-treating a well with pre-existing fractures which includes: displacing a tool in a well, leaking off motive fluid to an open fracture zone passed by the tool to diminish the rate of displacement, and locating the open fracture zone above the tool.

CROSS REFERENCE TO RELATED APPLICATION(S)

None.

BACKGROUND

Re-fracturing a well is a challenging operation, the success of which is in part dictated by the often unknown state of the well and associated formation at the start of the re-fracturing treatment. Often, the initial or previous fracturing treatment(s) has been designed to place several fractures along the wellbore. In the time between the fracturing treatment and the subsequent re-fracturing treatment, many parameters of the well may have changed, and/or parameters at the time of the fracturing may be otherwise unavailable, resulting in a number of unknown parameters which may impact the success of the re-fracturing treatment.

Examples of typical unknown parameters that affect the design and execution of a re-fracturing treatment may include the number and location of open fractures along the wellbore at the start of the re-fracturing treatment, pore pressure and its distribution profile, and stress variations along the wellbore, which may partially correlate with the pore pressure variations.

The industry is desirous of re-fracturing methods, systems and/or technology that efficiently address the existence of unknown parameters.

SUMMARY OF DISCLOSURE

In aspects, embodiments disclosed herein relate to methods of treating a subterranean formation, such as for example, a method of re-fracturing a well with pre-existing fractures, which include: deploying into the well a tool connected to surface by a cable; pumping a motive fluid into the well at a flow rate effective to displace the tool in the well past one or more open fracture zones; leaking off the motive fluid into the one or more open fracture zones passed by the tool, thus diminishing a rate of displacement of the tool relative to a rate of the pumping the motive fluid into the well, and locate the one or more open fracture zones above the tool; and treating at least one of the one or more open fracture zones located above the tool. In some embodiments, the method includes tensioning the cable to selectively leak off the motive fluid into the one or more open fractures passed by the tool. In some embodiments, the cable comprises a distributed measurement cable and/or the method includes conducting a distributed measurement survey along a length of the cable as it is deployed into the well.

In aspects, embodiments disclosed herein relate to methods of re-fracturing a well with pre-existing fractures, which include: deploying into the well a first tool connected to surface by a cable; pumping a motive fluid into the well to displace the first tool at a rate relative to a rate of the pumping of the motive fluid; displacing the first tool past an open fracture zone to locate the open fracture zone above the first tool; leaking off the motive fluid into the open fracture zone located above the first tool to diminish a rate of displacement of the tool relative to a rate of the pumping the motive fluid into the well; plugging one or more of the open fracture zones located above the first tool to at least partially restore the rate of displacement of the first tool relative to the rate of the pumping the motive fluid into the well; repeating the pumping (b), the displacement (c) and the leaking off (d) until the first tool reaches a first target depth; and treating a portion of the well located above the first target depth.

In further aspects, embodiments disclosed herein relate to methods of re-fracturing a well with pre-existing fractures, which include: deploying into the well a tool connected to surface by a cable; pumping a motive fluid into the well at a target flow rate to displace the tool in a bore of the well at a rate of displacement of the tool relative to a rate of increase of a volume of the motive fluid in the well bore; displacing the tool past a first fracture zone comprising at least one open fracture to leak off the motive fluid into the first fracture zone and diminish the rate of displacement of the tool in response to the leak off; stopping displacement of the tool at a first target depth below the first fracture zone; and re-fracturing the first fracture zone located above the first target depth.

Other aspects and advantages of the disclosure will be apparent from the following description and the appended claims.

BRIEF DESCRIPTION OF DRAWINGS

FIG. 1A schematically shows a well configuration according to first operational sequence in a re-fracturing method according to embodiments of the disclosure.

FIG. 1B schematically shows a well configuration according to second operational sequence in the re-fracturing method of FIG. 1A in accordance with embodiments of the present disclosure.

FIG. 2A schematically shows a well configuration according to first operational sequence in another re-fracturing method according to embodiments of the disclosure.

FIG. 2B schematically shows a well configuration according to second operational sequence in the re-fracturing method of FIG. 2A in accordance with embodiments of the present disclosure.

FIG. 2C schematically shows a well configuration according to third operational sequence in the re-fracturing method of FIGS. 2A and 2B in accordance with embodiments of the present disclosure.

FIG. 3A schematically shows a well configuration according to first operational sequence in another re-fracturing method according to embodiments of the disclosure.

FIG. 3B schematically shows a well configuration according to a second operational sequence in the re-fracturing method of FIG. 3A in accordance with embodiments of the present disclosure.

FIG. 3C schematically shows a well configuration according to a third operational sequence in the re-fracturing method of FIGS. 3A and 3B in accordance with embodiments of the present disclosure.

FIG. 4A schematically shows a well configuration according to first operational sequence in another re-fracturing method according to embodiments of the disclosure.

FIG. 4B schematically shows a well configuration according to a second operational sequence in the re-fracturing method of FIG. 4A in accordance with embodiments of the present disclosure.

FIG. 5A schematically shows a well configuration according to first operational sequence in another re-fracturing method according to embodiments of the disclosure.

FIG. 5B schematically shows a well configuration according to a second operational sequence in the re-fracturing method of FIG. 5A in accordance with embodiments of the present disclosure.

FIG. 5C schematically shows a well configuration according to third operational sequence in the re-fracturing method of FIGS. 5A and 5B in accordance with embodiments of the present disclosure.

FIG. 5D schematically shows a well configuration according to a fourth operational sequence in the re-fracturing method of FIGS. 5A, 5B, and 5C in accordance with embodiments of the present disclosure.

DEFINITIONS

“Above”, “upper”, “heel” and like terms in reference to a well, wellbore, tool, formation, refer to the relative direction or location near or going toward or on the surface side of the device, item, flow or other reference point, whereas “below”, “lower”, “toe” and like terms, refer to the relative direction or location near or going toward or on the bottom hole side of the device, item, flow or other reference point, regardless of the actual physical orientation of the well or wellbore, e.g., in vertical, horizontal, downwardly and/or upwardly sloped sections thereof.

Depth in when used in the present disclosure refer to any displacement or distance being horizontal, vertical or lateral.

Fracture shall be understood as one or more cracks or surfaces of breakage within rock. Fractures can enhance permeability of rocks greatly by connecting pores together, and for that reason, fractures are induced mechanically in some reservoirs in order to boost hydrocarbon flow. Fractures may also be referred to as natural fractures to distinguish them from fractures induced as part of a reservoir stimulation or drilling operation.

As used herein, an open zone, including an open fracture zone, refers to a zone in which there may be fluid communication between the formation and the wellbore extending through the formation. That is, such open zone may refer to an open hole or a section of an open hole (where no casing or liner is cemented in place, serving as a barrier between the formation and the wellbore), or to a cased well which has been modified to allow for such access to the formation. In one or more embodiments, such well may be a cased well with at least one perforation, perforation cluster, a jetted hole in the casing, a slot, at least one sliding sleeve or wellbore casing valve, or any other opening in the casing that provides communication between the formation and the wellbore.

The term “fracturing” refers to the process and methods of breaking down a geological formation and creating a fracture, i.e. the rock formation around a well bore, by pumping fluid at very high pressures (pressure above the determined closure pressure of the formation), in order to increase production rates from a hydrocarbon reservoir. The fracturing methods otherwise use conventional techniques known in the art.

The term “treatment”, or “treating”, refers to any subterranean operation that uses a fluid in conjunction with a desired function and/or for a desired purpose. The term “treatment”, or “treating”, does not imply any particular action by the fluid.

Fluid/Motive fluid shall be understood broadly, in the present context it may be the fluid injected into a well as part of a stimulation operation.

Past/passed when used in the present disclosure include near fracture or fractures that were partially past.

Distributed measurement cable may be understood as a cable enabling to record changes along a well such as for example temperature changes. Such distributed measurement can be achieved using various devices, an example may be a fiber-optic cable. The distributed temperature is measured by sending a pulse of laser light down the optical fiber. Molecular vibration, which is directly related to temperature, creates weak reflected signals. Such type of devices also enables measuring flow rates by creating a temperature transient and observing its movement along the well.

Cable include cables on which tools are lowered into the well and through which signals from the measurements are passed.

Monitoring shall be understood broadly as a technique to track the effect of the treatment.

Survey include the measurement versus depth or time, or both, of one or more physical quantities in or around a well. In the present disclosure the term may be used interchangeably with logs.

As used herein, the terms “plug”, “sealing agent” or “removable sealing agent” are used interchangeably and may refer to a solid or fluid that may plug or fill, either partially or fully, a portion of a subterranean formation. The portion to be filled may be a fracture that is opened, for example, by a hydraulic or acid fracturing treatment.

Isolating device in the present context include tools such as bridge plugs, cups or sealing elements such as packers.

Deploy shall be understood as running and potentially retrieve a tool in a wellbore. An example of conveyance mean suitable for deploying a toll may be a coiled tubing.

Leak off shall be understood as the fluid leaving the wellbore to enter in the formation. In shale formations, where the rock permeability is extremely small, the leak off requires a fracture which intersects the wellbore. In conventional formations, fluid may leak off in high permeability matrix of the rock such that zones which are not fractured may contribute to leak off

Logging shall be broadly interpreted as the operation of recording measurement in the wellbore.

Diverter in the present disclosure shall be understood as a chemical agent or mechanical device used in injection treatments, such as matrix stimulation, to ensure a uniform distribution of treatment fluid across the treatment interval. Injected fluids tend to follow the path of least resistance, possibly resulting in the least permeable areas receiving inadequate treatment. By using some means of diversion, the treatment can be focused on the areas requiring the most treatment. To be effective, the diversion effect should be temporary to enable the full productivity of the well to be restored when the treatment is complete. There are two main categories of diversion: chemical diversion and mechanical diversion. Chemical diverters function by creating a temporary blocking effect that is safely cleaned up following the treatment, enabling enhanced productivity throughout the treated interval. Mechanical diverters act as physical barriers to ensure even treatment.

DETAILED DESCRIPTION

In some embodiments the disclosure herein relates to a method of re-fracturing a well with pre-existing fractures, comprising: deploying into the well a tool connected to surface by a cable; pumping a motive fluid into the well at a flow rate effective to displace the tool in the well past one or more open fracture zones; leaking off the motive fluid into the one or more open fracture zones passed by the tool, to diminish a rate of displacement of the tool relative to a rate of the pumping the motive fluid into the well, and locate the one or more open fracture zones above the tool; and treating at least one of the one or more open fracture zones located above the tool. In some embodiments, the treating comprises re-fracturing at least one of the pre-existing fractures.

In some embodiments the method further comprises tensioning the cable to selectively leak off the motive fluid into the one or more open fractures passed by the tool. In some embodiments the cable comprises a distributed measurement cable and/or the method further comprises conducting a distributed measurement survey along a length of the cable as it is deployed into the well. In some embodiments the method further comprises conducting a distributed measurement survey along a length of the cable in the well, wherein the surveyed measurement is selected from the group consisting of temperature data, vibration data, strain data, or combinations thereof. Real-time measurements of cable temperature, temperature increase or decrease rate, vibration, and strain measurements are available to predict which fracture is taking more fluid. In some embodiments the cable comprises a distributed measurement cable, and the method further comprises obtaining measurements from the cable to determine the location of the one or more open fractures located above the tool.

In some embodiments the cable comprises a distributed measurement cable, and the method further comprises obtaining measurements from the cable to monitor execution of the treatment. In some embodiments the measurements obtained comprise fluid flow rate versus depth during the treatment to monitor fluid flow into the one or more open fracture zones located above the tool. In some embodiments the treatment comprises diverting a fracturing treatment fluid by placing a plug in at least one of the one or more open fracture zones located above the tool, and wherein the measurement of the fluid flow rate versus depth indicates the effectiveness of the plug, and/or further comprising reinforcing the plug if the plug is indicated to be ineffective.

In some embodiments the tool comprises an isolation device, a perforation tool, or a combination thereof. In some embodiments the method further comprises setting the device at a target depth to isolate the one or more open fracture zones located above the device for the re-fracturing, from a portion of the well below the device. In some embodiments the method further comprises determining the target depth as a location where a total rate of the motive fluid leak-off into the one or more open fracture zones located above the tool matches the flow rate of the motive fluid pumped into the well, wherein the displacement of the tool is diminished substantially to zero.

In some embodiments the method further comprises logging the location of the one or more open fracture zones located above the tool from measurement of the rates of displacement of the tool and pumping the motive fluid into the well.

In some embodiments a method of re-fracturing a well with a series of pre-existing open fracture zones comprises: deploying into the well a first tool connected to surface by a cable; pumping a motive fluid into the well to displace the first tool at a rate relative to a rate of the pumping of the motive fluid; displacing the first tool past an open fracture zone to locate the open fracture zone above the first tool; leaking off the motive fluid into the open fracture zone located above the first tool to diminish a rate of displacement of the tool relative to a rate of the pumping the motive fluid into the well; plugging one or more of the open fracture zones located above the first tool to at least partially restore the rate of displacement of the first tool relative to the rate of the pumping the motive fluid into the well; repeating the pumping (b), the displacement (c) and the leaking off (d) until the first tool reaches a first target depth; and treating a portion of the well located above the first target depth.

In some embodiments the cable gathers distributed measurement information to monitor any of (b), (c), (d), (e), (f), (g), or any combination thereof. In some embodiments the re-fracturing (g) introduces a fracturing fluid into one or more unplugged open fracture zones. In some embodiments the re-fracturing (g) comprises introducing a fracturing fluid and a diverter into the well to distribute the fracturing fluid into one or more of the pre-existing fracture zones, new fracture zones, or a combination thereof. In some embodiments the cable gathers distributed measurement information to monitor the distribution of the fracturing fluid.

In some embodiments the method further comprises repeating the plugging (e) and (f) a plurality of times until the first tool reaches the first target depth in the well. In some embodiments the first target depth is a toe of the well.

In some embodiments the method further comprises: (h) optionally repeating the plugging (e) and (f) a plurality of times until the first tool reaches the first target depth in the well, or setting the first tool at the first target depth for treating (g) at least once above the first target depth, or a combination thereof; (i) pulling the first tool up the well to a second target depth; (j) setting the first tool at the second target depth to isolate a portion of the well above the second target depth from a portion of the well below the second target depth; and (k) treating in the portion of the well isolated above the second target depth. In some embodiments the second target depth is above an open fracture zone located between the first and second target depths.

In some embodiments the method further comprises (l) pulling the first tool up the well to a successively higher target depth; (m) setting the first tool at the successively higher depth to isolate a portion of the well above the successively higher target depth from a portion of the well below the successively higher target depth; and (n) treating the portion of the well isolated above the successively higher target depth. In some embodiments the method further comprises repeating (l), (m), and (n) at least once more.

In some embodiments the method further comprises (h) optionally repeating the plugging (e) and (f) a plurality of times until the first tool reaches the first target depth in the well, or setting the first tool at the first target depth for re-fracturing (g) at least once above the first target depth, or a combination thereof; (i) optionally disconnecting and retrieving the cable from the first tool; (j) deploying a second tool into the well to a second target depth above the first target depth; (k) setting the second tool at the second target depth to isolate a portion of the well above the second target depth from a portion of the well below the second target depth; and (l) re-fracturing in the portion of the well isolated above the second target depth.

In some embodiments the method further comprises (m) deploying a successive tool into the well to a successively higher target depth; (n) setting the successive tool at the successively higher depth to isolate a portion of the well above the successively higher target depth from a portion of the well below the successively higher target depth; and (o) treating the portion of the well isolated above the successively higher target depth. In some embodiments the method further comprises repeating (m), (n), and (o) at least once more.

In some embodiments the plugging (e) comprises placing one or more degradable diverter plugs at one or more of the open fracture zones, respectively, and degrading at least one of the one or more degradable diverter plugs for the re-fracturing (g). In some embodiments the cable gathers distributed measurement information to monitor the degradation of the at least one of the one or more degradable diverter plugs, or to monitor the re-fracturing (g), or both. In some embodiments the cable gathers distributed measurement information to determine at least one of the one or more degradable diverter plugs has been degraded, and the method further comprises introducing a fracturing fluid into the at least one or more unplugged open fracture zones wherein the corresponding diverter plug has been determined to have been degraded.

In some embodiments a method of re-fracturing a well with pre-existing fractures comprises deploying into the well a tool connected to surface by a cable; pumping a motive fluid into the well at a target flow rate to displace the tool in a bore of the well at a rate of displacement of the tool relative to a rate of increase of a volume of the motive fluid in the well bore; displacing the tool past a first fracture zone comprising at least one open fracture to leak off the motive fluid into the first fracture zone and diminish the rate of displacement of the tool in response to the leak off; stopping displacement of the tool at a first target depth below the first fracture zone; and treating the first fracture zone located above the first target depth.

In some embodiments the method further comprises setting the tool at the first target depth to isolate the first fracture zone above the first target depth prior to re-fracturing (e). In some embodiments the first target depth corresponds to a location of the tool when the leak off of the motive fluid is substantially equal to or greater than the target pumping flow rate.

In some embodiments the method further comprises (f) placing diverter in the zone re-fractured in (e) to diminish a rate of the leak off to at least partially restore displacement of the tool in the well bore relative to the target pumping flow rate; (g) displacing the tool past a successive fracture zone comprising at least one open fracture to leak off the motive fluid into the successive fracture zone and diminish the rate of displacement of the tool in response to the leak off; (h) stopping displacement of the tool at a successive target depth below the successive fracture zone; and (i) re-fracturing the successive fracture zone located above the successive target depth.

The method of claim 34, further comprising: (j) placing diverter in the zone re-fractured in (i) to diminish a rate of the leak off to at least partially restore displacement of the tool in the well bore relative to the target pumping flow rate; and (k) repeating the displacement in (g), the stopping in (h), and the re-fracturing in (i). In some embodiments the method further comprises repeating (j) and (k) one or a plurality of additional times.

With reference to FIGS. 1A and 1B, well configurations according to some embodiments of an operational sequence are schematically illustrated. In FIG. 1A, a well 10 is shown with pre-existing open fractures or fracture zones 12, 14, 16, etc., the exact location and condition of which may not be known at the beginning of the operation. According to some embodiments, a tool 18 attached to a cable 20. In some embodiments, the tool 18 can be an isolation device, a perforating tool, a combination isolation device/perforating tool, a logging tool or the like. As non-limiting examples, the downhole tool 18 may be designed for isolation to deploy a bridge plug, retrievable or non-retrievable packer, or the like.

In some embodiments the cable 20 may include a a distributed measurement feature, which can obtain measurements distributed along its length, e.g., pressure, temperature, flow rate, or the like. One example of cable 20 may include a cable core. The cable core may include an optical fiber conductor. The optical fiber conductor may include a pair of half-shell conductors. An insulated optical fiber is located between the pair of half-shell conductors. The insulated optical fiber is coupled with the pair of half-shell conductors. The optical fiber conductor also includes an optical fiber conductor jacket disposed about the pair of half-shell conductors. In some embodiments, the tool 18 is pumped into the well 10 via a surface deployment system 22, which may include a truck and/or skid mounted unit or units for pumping, mixing, control, etc., for example. As motive fluid is pumped from the surface behind the tool 18, it is pushed down toward the toe 24 of the well 10. When the tool 18 is displaced past the uppermost open fracture 12, depending on the condition, e.g., conductivity, pore pressure, or the like, a portion of the motive fluid leaks off into the fracture 12 as indicated by the flow arrows 26 in FIG. 1A, and the rate of displacement relative to the motive fluid pumping rate at the surface, is diminished. If the rate of motive fluid pumping is constant, or is not increased sufficiently to match or exceed the leakoff rate, the displacement rate of the tool 18 will diminish accordingly.

In some embodiments, as the tool 18 continues its deployment down the well 10, the leakoff rate likewise increases as additional fractures such as fracture 14 are encountered and additional fluid leaks off at 28, as best seen in FIG. 1B. Where the leakoff 26, 28 occurs only at the fractures 12, 14, etc., the net flow rate into the well 10 for displacement of the tool 18 may decrease proportionally in some embodiments in discrete steps. Ultimately, when the net flow rate is insufficient for displacement, e.g., where the motive fluid is pumped at a constant rate and the tool 18 has an effectively neutral buoyancy (taking into account fluid loss below the tool 18), and the tool 18 may stop.

By observing the displacement rate and position of the tool 18, the location and other information about the fractures 12, 14 such as conductivity can be determined. In some embodiments, during the displacement of the tool downhole, the operator measures the displacement rate of the tool and logs leak-off in the open/conducive fractures 12, 14. In some embodiments, the operator may use this information, alone or also taking into account any distributed measurement cable, to draw a log of the open fractures located in this manner along the wellbore, which may later facilitate the execution of the re-fracturing or other treatment. In further embodiments, the tool 18 is provided with a displacement attenuation and/or gain functionality in such a way that the tool 18 is relatively sensitive to the change of flow rate due to leak-off, e.g., by increasing positive buoyancy of the tool 18 and/or tensioning the cable 18 in response to the detection of leak off and/or filling the well 10 with a fluid that is more viscous than the motive fluid before deployment of the tool 18 so that it leaks off more slowly into any open fractures below the tool relative to the leak off rate of the motive fluid and/or balancing pressure at the tool 18 above and below and/or fixing a pressure differential across the tool 18; or conversely, e.g., such that delta changes in the leakoff flow rate have to exceed predetermined or adjustable triggering rates to adjust displacement parameters such that a displacement rate of the tool is changed. In some embodiments according to the disclosure adding resistance to displacement of the tool 18 can enhance leakoff into open fractures above the tool 18 and inhibit leakoff into open fracture zones below the tool 18, such that identification of the open fracture zones and/or other fluid loss zones is facilitated.

In some embodiments as illustrated in FIG. 1B, the tool 18 may be set to isolate an upper section 32 of the well 10 in communication with the fractures 12, 14, from a lower section 32, which may contain additional fractures such as fracture 16. The “heel” fractures 12, 14 can then be treated with an appropriate treatment fluid pumped into the upper section 32 above the activated isolating tool 18. The fractures 12, 14 can be treated simultaneously or sequentially using one or more treatments available for fracturing and/or re-fracturing a well.

Where the cable 18 is provided with distributed measurement functionality in some embodiments, measurement information gathered along the length thereof may be used to monitor the leakoff (i.e., fracture) locations and quality during displacement of the tool 18, e.g., to confirm the displacement rate/depth observations. Also, in some embodiments, the measurement information can be observed during the re-fracturing or other treatment for monitoring of the fracturing treatment while (real-time) it is being executed, or afterwards. For example, it can be used in some embodiments to measure the fluid flow rate as a function of depth, information which can be used to monitor the volume and/or rate at which each fracture receives treatment fluid during the fracturing or other treatment, e.g., the manner in which the treatment fluid redistributes along the treated interval as the net pressure in each fracture zone varies and influences the flow profile; or the effectiveness of a seal, plug or diverter that may be located and/or removed at the fracture as part of the treatment process. Such information in some embodiments can facilitate adjustments to the treatment pumping or composition schedule, including the pumping rate and/or pressure, e.g., in fracturing treatments which use a diverter, where the effectiveness of the diverter at the plugged fractures can be monitored and corrective actions can be taken in response to the measurements observed during the treatment. For example, in some embodiments where excessive leakage is detected into a fracture zone at which diverter has been placed, an additional diverter treatment and/or diverter reinforcement treatment may be pumped to the fracture zone in question.

With reference to FIG. 2A, once the downhole tool 18 has reached the depth at which leakoff into open fracture zones 12, 14 etc. matches the motive fluid pumping rate and the displacement of the tool 18 is reduced, e.g., the tool 18 is immobilized, then rather than setting the tool 18 in place to isolate the upper “heel” section 32 from the lower “toe” section 30 of the wellbore 10 as in FIGS. 1A and 1B above, in some other embodiments according to the present disclosure, a slurry is pumped, which significantly lowers the rate of or eliminates the leakoffs of fluid to the formation by forming plugs 40, 42 as shown in FIG. 2B. In some embodiments, a leakoff control material or a diverter can be used, either with or without operating the tool 18 for isolation, to reduce a rate of the leakoff into the formation, as in US Patent application 20120285692, which is hereby incorporated herein by reference in its entirety. In consequence, the net flow rate in the wellbore 10 in some embodiments is reestablished at least in part, and the tool 18 can be re-mobilized to be displaced further down the well 10, as shown in FIG. 2C.

When the tool 18 passes the intersection of a successive fracture 16 giving rise to new leakoff 46, as shown in FIG. 2C, or a plurality of such fractures, the tool 18 may immobilize again. Options are then to pump more leakoff control material or diverter to place a plug and mobilize the tool 18 again (with or without isolation of tool 18) as in FIG. 2B, or to set the isolation tool 18 in place and fracture the section 32 above the tool 18, as in FIG. 1B.

According to some embodiments of the present disclosure, the tool 18 can be displaced all the way to or adjacent the toe 24 of the well 10, as shown in FIG. 3A, by using leakoff control material or diverter to form plugs 40, 42, and then once adjacent the toe of the well, a fracturing treatment can be pumped above the tool 18, with or without isolation of the tool 18. In some embodiments, the fracturing re-treatment treats (expands or re-opens) any pre-existing open fracture zones, that have not been previously plugged by the leakoff control material or diverter during the process of displacing the tool 18 to the toe 24, and/or creates fresh fracture zones in intervals not previously fractured, which in some embodiments may be located in the upper section 32 of the well 10 just above or adjacent to the tool 18, such as fracture zone 16.

After re-treatment of the lowermost open fracture zone 16 is completed, or completed to the extent the particular treatment is facilitated by maintaining the isolation effected by the tool 18 below the fracture zone 16, in some embodiments the tool 18 is raised above the treated fracture zone 16 and set above the zone 16 and below the next lowest fracture zone to be treated or re-treated, e.g., plugged fracture zone 14, as shown in FIG. 3B. In some embodiments, the fracture zone 14, now isolated by the relocated tool 18 above the treated or re-treated fracture zone 16, can be treated or re-treated by removing the plug 42 and supplying a treatment fluid into the re-opened fracture zone as shown in FIG. 3C. For example, the plug 42 can be removed in some embodiments by exposure to a treatment fluid containing a seal removal agent. If desired, other fracture zones above the isolation tool 18 may be treated concurrently and/or serially, e.g., by optionally relocating and setting the tool 18 above the previously treated zones, removing any associated plugs, and/or introducing a treatment fluid into the successively higher fracture zone(s), for example, by removing the plug 40 and introducing treatment fluid into the fracture zone 12, as shown in FIG. 3C.

During the re-fracturing or other re-treatment, according to all embodiments, the location of fractures which are being treated, e.g., by receipt of the treatment fluid, extension or expansion of pre-existing fractures, and/or creation of new fractures within the fracture zone, can be monitored by the distributed measurements along the cable going from surface to the tool. A diverter as discussed herein according to embodiments, can be used during the re-fracturing treatment itself for distribution of the treatment fluid flow to the pre-existing fractures and/or to generate new fracture zones along the wellbore. The effect of the diverter plugs placed during displacement of the tool, and/or placed during the re-fracturing or other re-treatment process, may be monitored by the distributed measurement cable.

As mentioned, in some embodiments, once the fracturing treatment of a lower fracture zone is completed, the cable 20 and the tool 18 can be raised in the well 10, i.e., “pulled out of the hole” (POOH), and set in place at a shallower depth in order to isolate an upper section 32 from a lower section 30 of the wellbore 10. The depth at which to pull the tool 18 and re-set it in place in some embodiments is determined on the basis of the distributed measurement via the cable 20, which highlights where the major open fractures 12, 14, 16 are located. For example, as shown in FIG. 3B, it may be desirable to set the isolating tool 18 just above a fracture that takes fluid, e.g., fracture zone 16, to isolate the fracture 16 from the upper section 32 of the wellbore 10 in which a subsequent fracturing treatment is pumped. In some embodiments, it may be desirable to set the isolating tool 18 at a depth shown schematically in FIG. 3C, perform a fracturing treatment on the upper section 32, e.g., treatment of fracture zones 12, and then further subdivide the interval of upper section 32 for one or more successive re-fracturing treatments, for example, by unsetting the tool 18 from its location in FIG. 3C and setting it at a successively shallower depth (not shown).

In some embodiments, the tool 18 may be a single-use isolation device, i.e., one that is abandoned in place downhole after being set as shown in FIG. 3A. In these embodiments, an option is to disengage the monitoring cable 20 from the isolating tool 18 in place in the well 10, then pull the cable 20 to surface, attach it to another instance of an isolating tool 18, and pump it to the target depth in FIGS. 3B and 3C, above the target depth in FIG. 3A.

In some embodiments as mentioned, with reference to FIGS. 4A and 4B, re-fracturing or other re-treatment of the open fracture zones 12, 14, 16 located above the isolation device 18, may as desired be concurrently or serially directed to only one, or a portion, or all of the fractures 12, 14, 16, that were plugged with respective plugs 40, 42, 44 (see FIG. 4A) in the step(s) of pushing or otherwise displacing the tool 18 downhole before initiating the fracturing treatment. If the diverter material is degradable, then in some embodiments a delay period can be provided for all or part of the diverter material to degrade from any or all of the plugs 40, 42, 44 before initiating the fracturing treatment, e.g., after the degradation of the plug 42 material, treatment of fracture zone 14 may be isolated from fracture zones 12, 16 located above and/or below which remain plugged by respective non-degraded plugs 40, 44, as shown in FIG. 4B. In some embodiments, the degradation of the material in the plugs 40, 42, 44 can be monitored by maintaining a positive pressure from wellbore 10 and monitoring the profile of fluid flow, e.g., via the distributed measurement cable 20, during the process of degradation of the diverting material. In some embodiments, once it is determined and/or confirmed via distributed measurement cable 20 that all fractures which were identified ‘open’ during pumping down the tool 18 and which are desired to be treated, are opened again by removal of the respective plugs, then the material in the plugs 40, 42 and/or 44 can be considered sufficiently degraded such that the respective open fractures 12, 14 and/or 16 are ready for initiation of the fracturing treatment and/or other receipt of treatment fluid.

With reference to the “heel-to-toe” sequence of operations illustrated schematically in FIGS. 5A to 5D, in some embodiments the isolation tool 18 is displaced partially down the well 10 and spaced above the toe 24 of the well before initiating a re-fracturing or other re-treatment. Conveniently, with reference to FIG. 5A, achievement the matching of the leakoff above the tool 18 to the rate of motive fluid pumping, i.e., immobilization of the tool 18 against displacement by continued pumping of the motive fluid, in some embodiments is interpreted as evidence that there are a plurality of open fractures 12, 14 in the upper section 32 of the well 10, which are susceptible to be ‘re-treated’ before moving further down the well 10.

In these embodiments, a fracturing treatment can be pumped with the downhole tool 18 and cable 20 in place, as illustrated schematically in FIG. 5B. In some embodiments, if desired, the tool 18 may be held in place by the cable 20 and/or selectively set mechanically and/or chemically to provide isolation between the upper zone 32 of the well 10, where the fracturing treatment fluid is injected, and the bottom zone 30 of the well 10 below the isolation device 18. The cable 20 in place, which connects the tool 18 to the surface, in some embodiments as mentioned, can if desired be used for real-time monitoring of the progress of the fracturing treatment, e.g., tracking temperatures, pressures, flow rates and/or other parameters along the length of the distributed measurement cable 20, and in the vicinity of the open fracture zones 12, 14 while undergoing treatment.

Once the fracturing treatment of the upper section 32 fracture zones 12, 14 is completed, a diverter may optionally be pumped, according to some embodiments, to form respective plugs 40, 42, to lower the leakoff rate into the upper fractures 12, 14, as seen in FIG. 5C. Once the leak-off rate is sufficiently diminished by the plugs 40, 42, then in some embodiments, it is possible to un-set the tool 18 where necessary, e.g., by mechanical and/or chemical operation, and displace the tool 18 to a depth further down the wellbore 10, as shown in FIG. 5C.

According to some embodiments as shown in FIG. 5D, one or more successive fracturing treatments can then be iteratively pumped each time the downhole tool 18 is advanced to a successive target depth, e.g., when the tool 18 stops at a depth wherein demobilization occurs again due to leakoff into one or more successive fractures such as fracture zone 16 located below the preceding treatment interval(s), e.g., the interval containing zones 12, 14. As mentioned, in various embodiments the tool 18 can be selectively set (mechanically and/or chemically), or simply held in place by the cable 20 during each successive fracturing operation, which may if desired, be repeated until the tool 18 reaches the toe 24 or other ultimate target depth.

In any of the embodiments discussed herein, the cable may be a monitor cable that is attached to either a temporary or permanent pump down assembly/plug, which may be operated mechanically, electrically, pneumatically, chemically and/or the like or any combination thereof. In some embodiments, the monitor cable can include any single technology or combination of the technologies selected from: Distributed Temperature (DTS), Distributed Vibration (DVS), Distributed measurement cable (combination of DTS, DTV, and the like.

In any of the embodiments discussed herein, the tool and monitor cable may include either a mechanical or electrical weak point for disengagement after operations, which may be activated to disengage the cable from the tool for selectively retrieving the cable. The tool may thus be selectively retrieved or abandoned downhole.

In some embodiments, fracture stimulation, e.g., re-fracturing or other treatment of the pre-existing and/or newly created fractures, for the stage may be initiated and pumped as per design using a degradable composite fluid, as described in US Patent application US20120285692, which is hereby incorporated by reference in its entirety. In some embodiments, stimulation fluid volumes may be monitored via the monitor cable to determine fluid injection profile, either real time and/or post stimulation, or both.

In any of the embodiments discussed herein, upon completion of the treatment or re-treatment stage, a degradable composite pill may be pumped for diversion and/or to otherwise form a seal or plug in or at the treated fracture zone, and if desired, the diversion may likewise be monitored via the monitor cable 20.

In the case of re-entry/re-fracturing, the number of stages and depth of stages may vary according to different embodiments, and if desired, depths and/or pumping schedules can be varied in response to information acquired with the monitor cable, e.g., in real time. In one or more embodiments, examples of sources of the information used for making such decisions may comprise magnitude of the treating pressure, temperature log data, microseismic including real-time microseismic data, or any other known sources of information that may be beneficial to the decision making process. In any of the embodiments discussed herein, this process may then be repeated until the number of stages in the section or well is completed, e.g., toe-to-heel, or heel-to-toe, or a combination thereof. In any of the embodiments discussed herein, once all stages are completed and/or it is otherwise desired to retrieve the cable 20 separately from the tool 18, the weak point or other disengagement feature may be activated to release the monitor cable 20 and the monitor cable 20 can be removed from the well 10.

In any of the embodiments discussed herein, once all stages are completed, the monitor cable may be placed or left at least temporarily at a desired depth in the well, e.g., along the length of any treated or other zones to be produced, while production flow back is initiated (or longer if desired), and the monitor cable can be used to collect data to determine a production flow profile. In these embodiments, the cable can be placed or left in the well at least until such time as the production monitor service is no longer required, or can be placed or left in the well for later re-establishment of production monitoring.

In some embodiments disclosed herein the plugs 40, 42, 44 used to seal the pre-existing and/or newly created fractures and the methods of using them may involve controllable and/or selective chemical induced zonal sealing/unsealing for treatment diversion during multistage well stimulation operations, such as, for example, dividing the wellbore 10 into multiple zones, e.g., well sections 30 and 32, plugging at least one fracture zone with one or more various removable sealing agents, then selectively removing the sealing agents and unsealing one or more previously sealed zones so that the unsealed zone(s) may be treated.

The embodiments of methods for selective zonal sealing/unsealing for treatment diversion between the stages of a multi-stage well presented herein are applicable for stimulating wells regardless of their completion type. The selectivity of the zonal sealing/unsealing as used herein may be conferred by either selective placement or selective reaction. Selective placement may involve selecting the location at which the sealing agent is applied or removed, which may be enabled by placing a tool at the depth where the sealing or removing takes place. For example, a coiled tubing line spotted at the depth where the sealing agent is to be removed may then use abrasive jet perforating to perforate through the seal or to spot a chemical capable of removing the seal. Selective reaction may involve a selective degradation time for the sealing agent or a selective chemical agent for removing selected sealing agents. In some embodiments, selective degradation may occur via a sealing agent degrading at a faster rate in the presence of a certain wellbore fluid or chemical than another sealing agent used to seal the wellbore. Selective reaction and removal of a sealing agent may occur when a chemical removing agent reacts or interacts with certain sealing agents while being substantially inert towards other sealing agents. For example, the chemical removing agent may react or interact to induce hydrolysis, oxidation, dissolution, and/or degradation of the sealing agent.

If further treatments of different zones of the wellbore are warranted or desired, the treated target zone of the wellbore may optionally be sealed with at least one or more removable sealing agents. It is another possibility to leave the treated target zone unsealed. The removable sealing agents sealing the next target zone(s) may be selectively removed to enable treatment of the next target zone(s). In this way, the treatment of the desired wellbore zone may be completed by repeating the process as many times as desired. Eventually, if no further treatments are warranted or desired, a final selective removal of at least one of the removable sealing agents in the sealed zones may be performed to reach the end of the job and allow for production through the wellbore.

As mentioned, the method may begin with a well having at least one zone open. In one or more embodiments, the well may not initially contain an open zone or may not contain an open zone in a desired portion of the well, and the open zone may be created by perforating the casing with perforating charges, jetting with a coiled tubing (CT) line or slick-line conveyed tools, cutting the casing, or any other known methods for creating an open zone in a well. In some embodiments, manipulating at least one sliding sleeve or wellbore casing valve within the wellbore or the creation of an open zone within a wellbore may enable access to an untreated zone of the formation.

At least one open zone may be sealed (temporarily) with a removable sealing agent that may be a dissolvable or otherwise removable composition. As used herein, sealing of an open zone (or zones) may involve reduction of a fluid's ability to flow from the wellbore into the open zone, which may include reduction in the permeability of the zone. As used herein, sealing an open zone refers to sealing the open zone at the sandface and does not involve plugging the wellbore itself, which is referred to instead as isolation of the wellbore. In particular, isolation may be used to isolate an entire section of the wellbore from any treatment or operations occurring in more upstream sections of the wellbore, whereas sealing, as used herein, leaves the wellbore open and instead seals the sandface.

The removable sealing agents may be any materials, such as solid materials (including, for example, degradable solids and/or dissolvable solids), that may be removed within a desired period of time. In some embodiments, the removal may be assisted or accelerated by a wash containing an appropriate reactant (for example, capable of reacting with one or more molecules of the sealing agent to cleave a bond in one or more molecules in the sealing agent), and/or solvent (for example, capable of causing a sealing agent molecule to transition from the solid phase to being dispersed and/or dissolved in a liquid phase), such as a component that changes the pH and/or salinity within the wellbore. In some embodiments, the removal may be assisted or accelerated by a wash containing an appropriate component that changes the pH and/or salinity. The removal may also be assisted by an increase in temperature, for example, when the treatment is performed before steam flooding, and/or a change in pressure.

In some embodiments, the removable sealing agents may be a degradable material and/or a dissolvable material. A degradable material refers to a material that will at least partially degrade (for example, by cleavage of a chemical bond) within a desired period of time such that no additional intervention is used to remove the seal. For example, at least 30% of the removable sealing agent may degrade, such as at least 50%, or at least 75%. In some embodiments, 100% of the removable sealing agent may degrade. The degradation of the removable sealing agent may be triggered by a temperature change, and/or by chemical reaction between the removable sealing agent and another reactant. Degradation may include dissolution of the removable sealing agent.

For the purposes of the disclosure, the removable sealing agents may have a homogeneous structure or may also be non-homogeneous including porous materials or composite materials. A removable sealing agent that is a degradable composite composition may comprise a degradable polymer mixed with particles of a filler material that may act to modify the degradation rate of the degradable polymer. In some embodiments, the particles of a filler material may be discrete particles. The particles of the filler material may be added to accelerate degradation and the filler particles may be from 10 nm to 5 microns in mean average size. In some embodiments, smaller filler particles may further accelerate degradation in comparison to larger filler particles. The filler particles may be water soluble materials, include hygroscopic or hydrophilic materials, a meltable material, such as wax, or be a reactive filler material that can catalyze degradation, such as a filler material that provides an acid, base or metal ion. In some embodiments, the filler particles may have a protective coating, thus allowing them to be mixed with a degradable polymer and/or heated during manufacturing processes, such as extrusion, whilst retaining their structural and compositional characteristics, the structural and compositional characteristics of the degradable polymer, and their capability for degradation. The coatings can also be chosen to delay degradation or fine tune the rate of degradation for particular conditions.

Examples of water soluble filler materials comprise NaCl, ZnCl₂, CaCl₂, MgCl₂, NaCO₃, KCO₃, KH₂PO₄, K₂HPO₄, K₃PO₄, sulfonate salts, such as sodium benzenesulfonate (NaBS), sodium dodecylbenzenesulfonate (NaDBS), water soluble/hydrophilic polymers, such as poly(ethylene-co-vinyl alcohol) (EVOH), modified EVOH, SAP (super absorbent polymer), polyacrylamide or polyacrylic acid and poly(vinyl alcohols) (PVOH), and the mixture of these fillers. Examples of filler materials that may melt under certain conditions of use include waxes, such as candelilla wax, carnauba wax, ceresin wax, Japan wax, microcrystalline wax, montan wax, ouricury wax, ozocerite, paraffin wax, rice bran wax, sugarcane wax, Paricin 220, Petrac wax 165, Petrac 215, Petrac GMS Glycerol Monostearate, Silicon wax, Fischer-Tropsch wax, Ross wax 140 or Ross wax 160. Examples of reactive filler materials that may accelerate degradation include metal oxides, metal hydroxides, and metal carbonates, such as Ca(OH)₂, Mg(OH)₂, CaCO₃, Borax, MgO, CaO, ZnO, NiO, CuO, Al₂O₃, a base or a base precursor. The degradable composites may also include a metal salt of a long chain (defined herein as ≧C8) fatty acids, such as Zn, Sn, Ca, Li, Sr, Co, Ni, K octoate, stearate, palmate, myrisate, and the like. In some embodiments, the degradable composite composition comprises a degradable PLA mixed with filler particles of either i) a water soluble material, ii) a wax filler, iii) a reactive filler, or iv) combinations thereof, said degradable composite may degrade in 60° C. water in less than 30, 14 or 7 days.

Solid removable sealing agents for use as the sealing agent may be in any suitable shape: for example, powder, particulates, beads, chips, or fibers, and may be a combination of shapes. When the removable sealing agent is in the shape of fibers, the fibers may have a length of from about 2 to about 25 mm, such as from about 3 mm to about 20 mm. In some embodiments, the fibers may have a linear mass density of about 0.111 dtex to about 22.2 dtex (about 0.1 to about 20 denier), such as about 0.167 to about 6.67 dtex (about 0.15 to about 6 denier). Suitable fibers may degrade under downhole conditions, which may include temperatures as high as about 180° C. (about 350° F.) or more and pressures as high as about 137.9 MPa (about 20,000 psi) or more, in a duration that is suitable for the selected operation, from a minimum duration of about 0.5, about 1, about 2 or about 3 hours up to a maximum of about 24, about 12, about 10, about 8 or about 6 hours, or a range from any minimum duration to any maximum duration.

The removable sealing agents may be sensitive to the environment, so dilution and precipitation properties may be taken into account when selecting the appropriate removable sealing agents. The removable sealing agent used as a sealer may survive in the formation or wellbore for a sufficiently long duration (for example, about 3 hours to about 6 hours). The duration may be long enough for wireline services to perforate the next pay sand, subsequent fracturing treatment(s) to be completed, and the fracture to close on the proppant before it completely settles, providing an improved fracture conductivity.

Further suitable removable sealing agents and methods of use thereof include those described in U.S. Patent Application Publication Nos. 2006/0113077, 2008/0093073, and 2012/0181034, the disclosures of which are incorporated by reference herein in their entireties. Such removable sealing agents include inorganic fibers, for example of limestone or glass, but are more commonly polymers or co-polymers of esters, amides, or other similar materials. They may be partially hydrolyzed at non-backbone locations. Any such materials that are removable (due in-part because the materials may, for example, degrade and/or dissolve) at the appropriate time under the encountered conditions may also be employed as removable sealing agents in the methods of the present disclosure. For example, polyols containing three or more hydroxyl groups may be used. Suitable polyols include polymeric polyols that solubilizable upon heating, desalination or a combination thereof, and contain hydroxyl-substituted carbon atoms in a polymer chain spaced from adjacent hydroxyl-substituted carbon atoms by at least one carbon atom in the polymer chain. The polyols may be free of adjacent hydroxyl substituents. In some embodiments, the polyols have a weight average molecular weight from about 5000 to about 500,000 Daltons or more, such as from about 10,000 to about 200,000 Daltons.

Further examples of removable sealing agents include polyhdroxyalkanoates, polyamides, polycaprolactones, polyhydroxybutyrates, polyethyleneterephthalates, polyvinyl alcohols, polyethylene oxide (polyethylene glycol), polyvinyl acetate, partially hydrolyzed polyvinyl acetate, and copolymers of these materials. Polymers or co-polymers of esters, for example, include substituted and unsubstituted lactide, glycolide, polylactic acid, and polyglycolic acid. For example, suitable removable materials for use as plugging agents include polylactide acid; polycaprolactone; polyhydroxybutyrate; polyhydroxyvalerate; polyethylene; polyhydroxyalkanoates, such as poly[R-3-hydroxybutyrate], poly[R-3-hydroxybutyrate-co-3-hydroxyvalerate], poly[R-3-hydroxybutyrate-co-4-hydroxyvalerate], and the like; starch-based polymers; polylactic acid and copolyesters; polyglycolic acid and copolymers; aliphatic-aromatic polyesters, such as poly(ε-caprolactone), polyethylene terephthalate, polybutylene terephthalate, and the like; polyvinylpyrrolidone; polysaccharides; polyvinylimidazole; polymethacrylic acid; polyvinylamine; polyvinylpyridine; and proteins, such as gelatin, wheat and maize gluten, cottonseed flour, whey proteins, myofibrillar proteins, caseins, and the like. Polymers or co-polymers of amides, for example, may include polyacrylamides.

Removable sealing agents, such as, for example, degradable and/or dissolvable materials, may be used in the sealing agent at high concentrations (such as from about 10 lbs/1000 gal to about 1000 lbs/1000 gal, or from about 30 lbs/1000 gal to about 750 lbs/1000 gal) in order to form temporary plugs or bridges. The removable material may also be used at concentrations at least 4.8 g/L (40 lbs/1,000 gal), at least 6 g/L (50 lbs/1,000 gal), or at least 7.2 g/L (60 lbs/1,000 gal). The maximum concentrations of these materials that can be used may depend on the surface addition and blending equipment available. [[convert to SI/metric]]

Suitable removable sealing agents also include dissolvable materials and meltable materials (both of which may also be capable of degradation). A meltable material is a material that will transition from a solid phase to a liquid phase upon exposure to an adequate stimulus, which is generally temperature. A dissolvable material (as opposed to a degradable material, which, for example, may be a material that can (under some conditions) be broken in smaller parts by a chemical process that results in the cleavage of chemical bonds, such as hydrolysis) is a material that will transition from a solid phase to a liquid phase upon exposure to an appropriate solvent or solvent system (that is, it is soluble in one or more solvents). The solvent may be the carrier fluid used for fracturing the well, or the produced fluid (hydrocarbons) or another fluid used during the treatment of the well. In some embodiments, dissolution and degradation processes may both be involved in the removal of the sealing agent.

Such removable sealing agents, for example dissolvable, meltable and/or degradable materials, may be in any shape: for example, powder, particulates, beads, chips, fibers, or a combination of shapes. When such material is in the shape of fibers, the fibers may have a length of about 2 to about 25 mm, such as from about 3 mm to about 20 mm. The fibers may have any suitable denier value, such as a denier of about 0.1 to about 20, or about 0.15 to about 6.

Examples of suitable removable fiber materials include polylactic acid (PLA) and polyglycolide (PGA) fibers, glass fibers, polyethylene terephthalate (PET) fibers, and the like.

In uncased wells, the zonal sealing of a specified open zone may generally be achieved by reducing the permeability of the formation rock by injecting viscous fluids into the specified zones. In one or more embodiments, the viscous fluids injected may comprise at least one of viscoelastic surfactant fluids, cross-linked polymer solutions, slick-water, foams, emulsions, dispersions of acid soluble particulate carbonates, dispersions of oil soluble resins, or any other viscosified fluid that may be subsequently dissolved or otherwise removed (such as by breaking of the viscosification).

For cased wells, zonal sealing of open zone(s) may be achieved by placing a solid removable sealing agent in the perforations or in the space between the formation rock and the casing. In one or more embodiments, the solid removable sealing agent may be a dissolvable material for zonal sealing, which may comprise acid soluble cement, calcium and/or magnesium carbonate, polyesters including esters of lactic hydroxycarbonic acids and copolymers thereof, active metals such as magnesium, aluminum, zinc, and their alloys, hydrocarbons with greater than 30 carbon atoms including, for example, paraffins and waxes, and carboxylic acids such as benzoic acid and its derivatives. Further, in one or more embodiments, the dissolvable solid removable sealing agent may be slightly soluble in a wellbore fluid at certain conditions and would have a long dissolution time in said fluid. Examples of combinations of removable sealing agents and wellbore fluids that result in slightly soluble dissolvable removable sealing agents are benzoic acid with a water-based wellbore fluid and rock salt with a brine in the wellbore fluid.

The solid removable sealing agent used for zonal sealing may be in any size and form: grains, powder, spheres, balls, beads, fibers, or other forms known in the art. In order to facilitate the delivery of the solid composition to the desired zone for sealing, the solid composition may be suspended in liquids such as gelled water, viscoelastic surfactant fluids, cross-linked fluids, slick-water, foams, emulsions, brines, water, and sea-water.

In one or more embodiments, the removable sealing agent may be a manufactured shape, at a loading sufficiently high to be intercepted in the proximity of the wellbore. The loading may be more than about 50 lb/1000 gal. The manufactured shape of the removable sealing agent may be round particles having dimensions that are optimized for sealing. Also, the particles may be of different shapes, such as cubes, tetrahedrons, octahedrons, plate-like shapes (flakes), oval, and the like. The removable sealing agent may be of any dimension that is suitable for sealing. For example, as described in U.S. Patent Application Publication No. 2012/0285692, the disclosure of which is incorporated by reference herein in its entirety, the removable sealing agent may including particles having an average particle size of from about 3 mm to about 2 cm. Additionally, the removable sealing agent may additionally include a second amount of particles having an average particle size from about 1.6 to about 20 times smaller than the first average particle size. Also, the removable sealing agent may include flakes having an average particle size up to 10 times smaller than the first average particle size.

In some embodiments, the removable sealing agent is a diverter pill. The diverter pill may be a diversion blend with fibers and degradable particles with a particular particle size distribution. The diverter pill may include about 2 to 100 bbl of a carrier fluid. The diverter pill may include a diversion blend that is used as a plug and may have a mass of 10 to 400 lbs. The diversion blend may include about 20 pounds to 200 lbs of fiber per 1000 gallons of blend. It may include about 20 to about 200 pounds of particles per 1000 gallons of blend. The diverter may include beads with an average size such as described in TABLE 1 of U.S. Patent Application Publication No. 2012/0285692 A1, which is hereby incorporated by reference in its entirety. Additionally, any other diverters that are used in the industry may qualify as removable sealing agents.

The delivery and placement of the removable sealing agent (including viscous fluids and solid compositions) for zonal sealing may be performed by bullheading the material downhole, spotting the material at the wellbore with a CT-line or slick-line, or by using downhole containers capable of releasing the material at a desired zone. In one or more embodiments, after spotting the removable sealing agent composition in the wellbore the removable sealing agent is injected into the zone to be sealed by increasing the pressure in the wellbore. Any excess of the removable sealing agent applied downhole may be removed from the wellbore by cleaning it out using a coiled tubing or washing line and an appropriate cleaner for the sealing material.

The mechanical strength of the removable seals created during the zonal sealing may be increased by compacting the removable seals with gluing systems such as epoxy resins or emulsion systems such as wax and paraffin emulsions. In one or more embodiments, the gluing systems for increasing the mechanical strength of the removable seals may be compounded with the solid removable sealing agent before placement in the wellbore or may be injected separately into the wellbore after sealing the zone with the removable sealing agent. An increase in the mechanical strength of the removable seals may also be achieved by compounding the solid removable sealing agents with at least one reinforcement agent chosen from the group including fibers, deformable particulates, and particles coated with temperature and/or chemically activated formaldehyde resins.

Further, as mentioned above, for cased holes, the workflow of the present disclosure may also include creating openings in the casing to create the one or more open zones and enable access to the formation. It is also within the scope of the present disclosure that zonal sealing may be combined with the creation of the open zone(s). For example, a sequence may include creation of open zone 1, sealing of open zone 1, creation of open zone 2, sealing of open zone 2, etc., which may be performed as many times as desired, and in combination with wellbore clean out if desired. This procedure may allow for the selective sealing of various wellbore zones with various removable sealing agents.

Once a target zone or zones has had its removable sealing agent selectively removed, treatment of the target zone may be performed. Further, as one or more other zones may still be sealed with removable sealing agents, such sealed zones may not be subjected to the treatment at the given stage, and in fact, may be inaccessible to such treatments given the removable sealing agent in place. In one or more embodiments, the at least one treatment may be a propped fracturing treatment, a non-propped fracturing treatment, a slick-water treatment, an acidizing acid fracturing, and/or an injection of chelating agents. The injecting fluid may be selected from one of water, slick-water, gelled water, brines, viscoelastic surfactants, cross-linked fluids, acids, emulsions, energized fluids, foams, and mixtures thereof.

Assuming one or more zones remain sealed (and such zones warrant treatment), after performing the at least one treatment stage, the treated zone may optionally be isolated or sealed in order to temporarily decrease or stop fluid penetration therein. This isolation or sealing may be achieved by several methods including plugging the perforations, the wellbore, or the annulus space between the casing and the borehole in the treated zone, including use of the various removable sealing agents described above. However, it is also within the scope of the present disclosure that conventional zonal isolation and diversion techniques may be used to isolate the treated zone such as pumping degradable and/or soluble ball sealers, setting sand or proppant plugs, setting packers, and bridge plugs including flow-through bridge plugs, and using completion conveyed tools such as sliding sleeves and wellbore valves. While sealing has been used to describe the sealing of the sandface, leaving the wellbore open, isolation is used to describe the complete closing off of a section or zone of the wellbore. When conventional zonal isolation and diversion techniques are utilized to effectively isolate a treated zone, the de-isolation of the treated zone may be performed by conventional techniques known in the art such as creating pressure draw across the casing to remove ball sealers from the perforation tunnels, wellbore clean out with a coiled tubing line, unsetting bridge plugs or milling them out, etc.

As mentioned above, the treated target zone may be sealed through the use of various removable sealing agents described above. For example, sealing of the treated zone may also be achieved using various particulate materials such as rock salt, oil-soluble resins, waxes, carboxylic acids, cements including acid soluble cements, ceramic beads, glass beads, and cellophane flakes. Additionally, permeability reduction in the treated target zone may be achieved by injecting viscous fluids, foams, emulsions, cross-linked fluids, viscoelastic surfactant fluids, brines, and mixtures thereof into the treated formation zone. Permeability reduction in the treated formation zone may also be achieved by injecting suspensions of solids such as carbonates, polyesters, rock salt, oil-soluble resins, waxes, carboxylic acids, and mixtures thereof.

In one or more embodiments, modification of the stress field in the treated zone may also be a way of sealing the target zone after treatment. Modifying the stress field in a treated target zone of the formation may be achieved by increasing the pore pressure in the treated target zone by injecting fluids including water, oil, foams, emulsions, cross-linked fluids, viscoelastic solid fluids, brines, and mixtures thereof. Alternatively, or in addition, the stress field may be modified by cooling or heating the formation rock in the treated target zone by using downhole heaters or coolers, or injecting heated or cooled fluids including energized fluids and gases in the treated zone of the formation.

As the operation progresses beyond the initially treated target zone(s), at least one of the sealed open zones may be selectively unsealed. That is, one or more wellbore zones sealed may be selectively unsealed to facilitate their treatment during the multi-stage treatment process. For embodiments using a solid, dissolvable component as the removable sealing agent, the selective unsealing of at least one sealed wellbore zone may be accomplished by contacting the removable sealing agent comprising the solid, dissolvable component with a suitable dissolving agent to dissolve the dissolvable component. In one or more embodiments, suitable dissolving agents may comprise at least one of inorganic acids (such as hydrochloric acid), organic acids (such as formic acid, acetic acid), hydroxides, ammonia, organic solvents, diesel, oil, water, brines, solutions of organic and/or non-organic salts, and mixtures thereof. For example, the dissolvable components calcium carbonate, boric acid, and paraffin are selectively dissolvable by 10% HCl, 10% NaOH, and hexane, respectively, while remaining substantially insoluble when contacted by other dissolving agents. In one or more other embodiments in which viscous fluids are used as the sealing material, the viscous fluids may be broken by breaker fluids known to reduce the viscosity thereof. For example, viscoelastic surfactants containing a quaternary amine group may possess a pH-dependent viscosity profile such that the fluid viscosifies at certain pH values, and may have a reduced viscosity at a lower pH value.

The delivery and placement of the dissolving agent or breaker for the selective removal of the removable sealing agent may be performed by bullheading the dissolving agent or breaker downhole, spotting the dissolving agent or breaker at the wellbore with tubing or a coiled tubing string (including any tubing with an inner diameter less than 1 inch), or by using downhole containers capable of releasing the dissolving agent or breaker at the sealed zone to dissolve or otherwise break the removable sealing agent. When using a fluid flush to deliver the dissolving agent or breaker to a sealed zone, it may be desirable to minimize contact of the fluid including the dissolving agent or breaker with sealed zones that are not intended to have the removable sealing agent removed and be unsealed, while maximizing the contact of the fluid including the dissolving agent or breaker with the sealed target zone or zones that are intended to have the removable sealing agent removed and be unsealed.

As mentioned above, in one or more embodiments, the aforementioned stages of treating the target zone, optional isolation or re-sealing of the treated target zone at stage, and/or selectively removing the removable sealing agent from a different untreated target zone may be repeated as many times as desired for the multi-stage treating of the specified wellbore interval. The decision about each stage and treatment continuation may be made on the multi-stage treatment job design and/or on data obtained during the multi-stage treatment process.

Specifically, in one or more embodiments, a cased wellbore open zone sealing may utilize a sequence, performed at least one time, comprising creating an open zone in the casing and sealing the created open zone with a removable sealing agent. Utilizing this sequence may allow for the sealing of the created wellbore zones with solid removable sealing agents comprising different dissolvable components. For example, the three solid dissolvable components may be used in a system for sealing at least three different zones, each with a different solid removable sealing agent. Thus, in one or more embodiments, a zonal sealing method may utilize a sequence of creating and/or sealing a first open zone with a solid removable sealing agent comprising a first dissolvable component, creating and/or sealing a second open zone with a solid removable sealing agent comprising a second dissolvable component, and repeating the sealing process with different dissolvable components as many times as desired for the chosen treatment process. In particular embodiments, the steps of using a dissolving agent to selectively unseal a previously sealed zone to create an opened target zone and performing a treatment on the created open target zone may be substituted anywhere in the sequence recited above.

Eventually, after the desired zones have been treated, communication between sealed or isolated zones and the wellbore may be reestablished so that the job can be completed and the wellbore can be put into production. The sealed and isolated zones of the wellbore may be unsealed and de-isolated using the techniques described above. Specifically, de-isolation techniques may include, for example, creation of pressure draw across a casing to remove ball sealers from perforation tunnels, wellbore clean-out with coiled tubing, unsetting bridge plugs and milling them out, etc.

In some embodiments, the multi-stage treatment method outlined above may be applied to wellbores that have zones that have previously undergone stimulation treatments. In this way, the wellbore may undergo re-stimulation treatments of the previously treated zones or the removable sealing agents may serve to seal the previously treated zones while untreated zones undergo stimulation treatments via a multi-stage treatment method. Types of treatments that zones of a wellbore may have undergone or that may be repeated (re-stimulation) during embodiments of a multi-stage treatment method described herein generally include fracturing operations, high-rate matrix treatments and acid fracturing, matrix acidizing, and injection of chelating agents.

In one or more embodiments, in a wellbore that has at least one zone that has previously undergone stimulation treatments there may exist at least one open zone. The at least one open zone may be one of the zones of the wellbore that has previously undergone stimulation treatments or the open zone may not have previously undergone stimulation treatments. Additionally, there may be a combination of open zones that have been treated along with zones that have not previously undergone stimulation treatments. Subsequently, at least one open zone of the wellbore may be sealed with one or more removable sealing agents, while leaving at least one open zone unsealed. The at least one open zone may then be treated while the at least on other zone is sealed. Following the treatment, access may be enabled to at least one zone. In some embodiments, enabling access to at least one zone may include selectively removing at least one removable sealing agent from a zone that was previously sealed. In some embodiments, enabling access may include creating an open zone by perforating the wellbore casing with perforating charges, jetting with a coiled tubing (CT) line or slick-line conveyed tools, cutting the casing, manipulating at least one sliding sleeve or wellbore casing valve within the wellbore or any other known methods for creating an open zone in a well. In some embodiments, manipulating at least one sliding sleeve or wellbore casing valve within the wellbore or the creation of an open zone within a wellbore may enable access to an untreated zone of the formation.

Further, it is also within the scope of the present disclosure that creation of openings in a casing may involve controlled dissolution of a sealing material that is in a plugged or sealed zone. In such a case, the removable sealing agent may be slightly soluble in a wellbore fluid at certain conditions and would have a long dissolution time in said fluid. Upon extended exposure to such wellbore fluid, the removable sealing agent may dissolve and reveal openings. Examples of combinations of removable sealing agents providing slightly soluble dissolvable components are benzoic acid with a water-based wellbore fluid as the dissolving agent and rock salt with brine in the wellbore fluid as the dissolving agent.

Although only a few example embodiments have been described in detail above, those skilled in the art will readily appreciate that many modifications are possible in the example embodiments without materially departing from this invention. For example, any embodiments specifically described may be used in any combination or permutation with any other specific embodiments described herein. Accordingly, all such modifications are intended to be included within the scope of this disclosure as defined in the following claims. In the claims, means-plus-function clauses are intended to cover the structures described herein as performing the recited function and not only structural equivalents, but also equivalent structures. Thus, although a nail and a screw may not be structural equivalents in that a nail employs a cylindrical surface to secure wooden parts together, whereas a screw employs a helical surface, in the environment of fastening wooden parts, a nail and a screw may be equivalent structures. It is the express intention of the applicant not to invoke 35 U.S.C. §112, paragraph 6 for any limitations of any of the claims herein, except for those in which the claim expressly uses the words ‘means for’ together with an associated function. 

What is claimed is:
 1. A method of re-fracturing a well with pre-existing fractures, comprising: deploying into the well a tool connected to surface by a cable; pumping a motive fluid into the well at a flow rate effective to displace the tool in the well past one or more open fracture zones; leaking off the motive fluid into the one or more open fracture zones passed by the tool, to diminish a rate of displacement of the tool relative to a rate of the pumping the motive fluid into the well, and locate the one or more open fracture zones above the tool; and re-fracturing at least one of the one or more open fracture zones located above the tool.
 2. The method of claim 1, further comprising tensioning the cable to selectively leak off the motive fluid into the one or more open fractures passed by the tool.
 3. The method of claim 1, wherein the cable comprises a distributed measurement cable.
 4. The method of claim 1, further comprising conducting a distributed measurement survey along a length of the cable as it is deployed into the well.
 5. The method of claim 1, further comprising conducting a distributed measurement survey along a length of the cable in the well, wherein the surveyed measurement is selected from the group consisting of temperature, vibration data, strain data, and combinations thereof.
 6. The method of claim 1, wherein the cable comprises a distributed measurement cable, and further comprising obtaining measurements from the cable to determine the location of the one or more open fractures located above the tool.
 7. The method of claim 1, wherein the cable comprises a distributed measurement cable, and further comprising obtaining measurements from the cable to monitor execution of the re-fracturing.
 8. The method of claim 7, wherein the measurements obtained comprise fluid flow rate versus depth during the re-fracturing to monitor fluid flow into the one or more open fracture zones located above the tool.
 9. The method of claim 8, wherein the re-fracturing comprises diverting a re-fracturing treatment fluid by placing a plug in at least one of the one or more open fracture zones located above the tool, and wherein the measurement of the fluid flow rate versus depth indicates the effectiveness of the plug, and further comprising reinforcing the plug if the plug is indicated to be ineffective.
 10. The method of claim 1, wherein the tool comprises an isolation device, a perforation tool, or a combination thereof.
 11. The method of claim 1, comprising setting the tool at a target depth to isolate the one or more open fracture zones located above the tool for the re-fracturing, from a portion of the well below the tool.
 12. The method of claim 11, comprising determining the target depth as a location where a total rate of the motive fluid leak-off into the one or more open fracture zones located above the tool matches the flow rate of the motive fluid pumped into the well, wherein the displacement of the tool is diminished substantially to zero.
 13. The method of claim 1, further comprising logging the location of the one or more open fracture zones located above the tool from measurement of the rates of displacement of the tool and pumping the motive fluid into the well.
 14. A method of re-fracturing a well with a series of pre-existing open fracture zones, comprising: (a) deploying into the well a first tool connected to surface by a cable; (b) pumping a motive fluid into the well to displace the first tool at a rate relative to a rate of the pumping of the motive fluid; (c) displacing the first tool past an open fracture zone to locate the open fracture zone above the first tool; (d) leaking off the motive fluid into the open fracture zone located above the first tool to diminish a rate of displacement of the tool relative to a rate of the pumping the motive fluid into the well; (e) plugging one or more of the open fracture zones located above the first tool to at least partially restore the rate of displacement of the first tool relative to the rate of the pumping the motive fluid into the well; (f) repeating the pumping (b), the displacement (c) and the leaking off (d) until the first tool reaches a first target depth; and (g) re-fracturing a portion of the well located above the first target depth.
 15. The method of claim 14, wherein the cable gathers distributed measurement information to monitor any of (b), (c), (d), (e), (f), (g), or any combination thereof.
 16. The method of claim 14, wherein the re-fracturing (g) introduces a fracturing fluid into one or more unplugged open fracture zones.
 17. The method of claim 14, wherein the re-fracturing (g) comprises introducing a fracturing fluid and a diverter into the well to distribute the fracturing fluid into one or more of the pre-existing fracture zones, new fracture zones, or a combination thereof.
 18. The method of claim 17, wherein the cable gathers distributed measurement information to monitor the distribution of the fracturing fluid.
 19. The method of claim 14, further comprising repeating the plugging (e) and (f) a plurality of times until the first tool reaches the first target depth in the well.
 20. The method of claim 14, wherein the first target depth is a toe of the well.
 21. The method of claim 14, further comprising: (h) optionally 1) repeating the plugging (e) and (f) a plurality of times until the first tool reaches the first target depth in the well, or 2) setting the first tool at the first target depth for re-fracturing (g) at least once above the first target depth, or 3) a combination thereof; (i) pulling the first tool up the well to a second target depth; (j) setting the first tool at the second target depth to isolate a portion of the well above the second target depth from a portion of the well below the second target depth; and (k) re-fracturing in the portion of the well isolated above the second target depth.
 22. The method of claim 21, wherein the second target depth is above an open fracture zone located between the first and second target depths.
 23. The method of claim 21, further comprising: (l) pulling the first tool up the well to a successively higher target depth; (m) setting the first tool at the successively higher depth to isolate a portion of the well above the successively higher target depth from a portion of the well below the successively higher target depth; and (n) re-fracturing in the portion of the well isolated above the successively higher target depth.
 24. The method of claim 23, further comprising repeating (l), (m), and (n) at least once more.
 25. The method of claim 14, further comprising: (h) optionally a. repeating the plugging (e) and (f) a plurality of times until the first tool reaches the first target depth in the well, or b. setting the first tool at the first target depth for re-fracturing (g) at least once above the first target depth, or c. a combination thereof; (i) optionally disconnecting and retrieving the cable rom the first tool; (j) deploying a second tool into the well to a second target depth above the first target depth; (k) setting the second tool at the second target depth to isolate a portion of the well above the second target depth from a portion of the well below the second target depth; and (l) re-fracturing in the portion of the well isolated above the second target depth.
 26. The method of claim 25, further comprising: (m) deploying a successive tool into the well to a successively higher target depth; (n) setting the successive tool at the successively higher depth to isolate a portion of the well above the successively higher target depth from a portion of the well below the successively higher target depth; and (o) re-fracturing in the portion of the well isolated above the successively higher target depth.
 27. The method of claim 26, further comprising repeating (m), (n), and (o) at least once more.
 28. The method of claim 14, wherein the plugging (e) comprises placing one or more degradable diverter plugs at one or more of the open fracture zones, respectively, and degrading at least one of the one or more degradable diverter plugs for the re-fracturing (g).
 29. The method of claim 28, wherein the cable gathers distributed measurement information to monitor the degradation of the at least one of the one or more degradable diverter plugs, or to monitor the re-fracturing (g), or both.
 30. The method of claim 28, wherein the cable gathers distributed measurement information to determine at least one of the one or more degradable diverter plugs has been degraded, and further comprising introducing a fracturing fluid into the at least one or more unplugged open fracture zones wherein the corresponding diverter plug has been determined to have been degraded.
 31. A method of re-fracturing a well with pre-existing fractures, comprising: (a) deploying into the well a tool connected to surface by a cable; (b) pumping a motive fluid into the well at a target flow rate to displace the tool in a bore of the well at a rate of displacement of the tool relative to a rate of increase of a volume of the motive fluid in the well bore; (c) displacing the tool past a first fracture zone comprising at least one open fracture to leak off the motive fluid into the first fracture zone and diminish the rate of displacement of the tool in response to the leak off; (d) stopping displacement of the tool at a first target depth below the first fracture zone; and (e) re-fracturing the first fracture zone located above the first target depth.
 32. The method of claim 31, further comprising setting the tool at the first target depth to isolate the first fracture zone above the first target depth prior to re-fracturing (e).
 33. The method of claim 31, wherein the first target depth corresponds to a location of the tool when the leak off of the motive fluid is substantially equal to or greater than the target pumping flow rate.
 34. The method of claim 31, further comprising: (f) placing diverter in the zone re-fractured in (e) to diminish a rate of the leak off to at least partially restore displacement of the tool in the well bore relative to the target pumping flow rate; (g) displacing the tool past a successive fracture zone comprising at least one open fracture to leak off the motive fluid into the successive fracture zone and diminish the rate of displacement of the tool in response to the leak off; (h) stopping displacement of the tool at a successive target depth below the successive fracture zone; and (i) re-fracturing the successive fracture zone located above the successive target depth.
 35. The method of claim 34, further comprising: (j) placing diverter in the zone re-fractured in (i) to diminish a rate of the leak off to at least partially restore displacement of the tool in the well bore relative to the target pumping flow rate; and (k) repeating the displacement in (g), the stopping in (h), and the re-fracturing in (i).
 36. The method of claim 35, further comprising repeating (j) and (k) one or a plurality of additional times.
 37. The method of claim 1, further comprising sealing at least one open fracture zone of the well with at least one removable sealing agent, selectively removing the removable sealing agent from at least one target zone, and re-fracturing the at least one target zone.
 38. The method of claim 37, wherein the re-fracturing occurs while at least one open fracture zone of the well is sealed with at least one removable sealing agent.
 39. The method of claim 37, wherein at least one of: sealing at least one open fracture zone of the well with at least one removable sealing agent, selectively removing the removable sealing agent from the at least one target zone, or the re-fracturing of the at least one target zone, is repeated at least one time.
 40. The method of claim 37, further comprising isolating at least one section of the well.
 41. The method of claim 38, further comprising unisolating the isolated section of the well.
 42. The method of claim 39, wherein during the repeating, multiple zones are re-fractured and form a first interval of the well, which upon completion of their re-fracturing the first interval is isolated and at least one more interval comprising a plurality of well zones is re-fractured in a substantially similar manner.
 43. The method of claim 37, further comprising sealing the re-fractured target zone with at least one removable sealing agent.
 44. The method of claim 37, wherein the selective removing comprises at least one of perforating, abrading, dissolving, hydrolyzing, oxidizing, degrading, or melting the removable sealing agent from at least one sealed target zone.
 45. The method of claim 37, wherein the selective removal of the removable sealing agent comprises contacting the at least one target zone with a removal agent by bullheading the removal agent downhole, spotting the removal agent downhole, the use of downhole containers to deliver the removal agent, or a combination thereof.
 46. The method of claim 45, wherein the removal agent dissolves the removable sealing agent; and wherein the removal agent is at least one of hydrochloric acid, formic acid, acetic acid, hydroxides, ammonia, organic solvents, diesel, oil, water, brines, solutions of organic or non-organic salts, and mixtures thereof.
 47. The method of claim 37, wherein the re-fracturing comprises at least one of a propped fracturing, a non-propped fracturing, a slick-water, acidizing, acid fracturing, injection of chelating agents, stimulating, or squeezing a chemical.
 48. The method of claim 37, wherein the removable sealing agent comprises a viscous fluid from at least one of gelled water, viscoelastic surfactant fluids, crosslinked polymer solutions, slick-water, foams, emulsions, dispersions of acid soluble solid particulates, dispersions of oil-soluble resins, and mixtures thereof.
 49. The method of claim 37, wherein the removable sealing agent comprises a solid material comprising at least one of acid soluble cement, calcium carbonate, magnesium carbonate, polyesters, magnesium, aluminum, zinc, and their alloys, hydrocarbons with greater than 30 carbon atoms, and carboxylic acids and derivatives thereof.
 50. The method of claim 37, wherein the removable sealing agent comprises manufactured shapes selected from at least one of particulates, sized particulates, fibers, flakes, rods, pellets and combinations thereof.
 51. The method of claim 37, wherein the removable sealing agent comprises a degradable composite material comprising a degradable polymer mixed with particles of a filler material.
 52. The method of claim 37, wherein the sealing comprises placing the removable sealing agent in a desired zone in the wellbore by at least one of bullheading the removable sealing agent downhole, spotting the removable sealing agent downhole, or using downhole containers to deliver the removable sealing agent.
 53. The method of claim 52, wherein the sealing further comprises: injecting the sealing material into the selected zone by increasing pressure in the well.
 54. The method of claim 37 wherein at least one seal of the sealed zones is mechanically strengthened by compacting the seal with an epoxy resin gluing system or an emulsion comprising wax or paraffin.
 55. The method of claim 37, wherein at least two zones are sealed with two distinct removable sealing agents which possess the capability of being removed by dissimilar removal processes.
 56. The method of claim 37, further comprising sealing the re-fractured zone(s) by at least one of plugging of perforations and/or well or annulus space between a casing and a borehole, reducing permeability of formation rock, modifying the stress field, or changing formation fluid pressure.
 57. The method of claim 1, further comprising: isolating, or sealing with a removable sealing agent, or a combination thereof, all but one of a plurality of the open fracture zones; re-fracturing the open fracture zone while the other zones are isolated or sealed or a combination thereof; sealing the re-fractured zone or isolating the section of the wellbore comprising the re-fractured zone; selectively removing the removable sealing agent from an untreated sealed zone; and repeating the sequence of re-fracturing the open fracture zone while the other zones are isolated or sealed, isolating or sealing the re-fractured zone, and selectively removing the removable sealing agent from a sealed un-re-fractured zone until the desired number of zones are re-fractured. 